This disclosure relates in general to immersion probes and, but not by way of limitation, to immersion probes utilized for detecting the first appearance of water in a multiphase flow in a well and measuring hydrate-inhibitor fraction in water for determining proper hydrate-inhibitor injection rates within oil and gas wells for flow assurance.
In both natural gas and crude oil wells, hydrate formation can occur at low temperatures (e.g., a few degree Celsius) and high pressures. This is due to the presence of water that is co-produced within the majority of natural gas or oil producing wells. In subsea or deepwater gas wells, for example, the aforementioned conditions of low temperature and high-pressure flows are typical. Within these wells, gas hydrate, an ice-like structure of crystalline solid consisting of water and gas molecules, can form, if not inhibited by antifreeze chemical injection in long subsea flow pipelines. The detection of the onset of water and/or water breakthrough in subsea gas wells is therefore important to flag the risk of pipeline blockage by hydrate formation and hence to identify a need for injection of the correct amount of hydrate inhibitors, such as glycols and/or other types of alcohols. The detection of formation saltwater breakthrough into a well/pipeline is also important, since in such an occurrence corrosion inhibitors may be needed to be injected to prevent the saltwater corroding the pipeline and/or wellbore system. Detection of the saltwater breakthrough is also important because the presence of salt within the produced water can affect the properties of the multiphase flow of hydrocarbons influencing important multiphase flow measurements as well as the hydrate formation temperature.
To combat hydrate-formation problems, thermodynamic inhibitors are used in addition to insulated flow pipes in subsea or deepwater. These inhibitors lower the temperature and pressures at which hydrates form within the pipeline. Other inhibitors, such as low dosage hydrate inhibitors, or kinetic inhibitors, may completely diminish hydrate formation, while functioning at substantially lower temperatures and higher pressures within a well pipe. In use, the inhibitors are pumped into the well pipeline to help ensure that no crystals will form and impede flow and/or block the pipe. However, hydrate inhibitors are expensive, and pumping large amounts into the wells/pipelines greatly increases production costs. Hydrates are also thermodynamically suppressed by the presence of antifreeze materials such as salts; as such, a common practice is to introduce, for example, 20 to 23 percent by weight (wt. %) of sodium chloride (NaCl) into the well/pipeline to address hydrate issues. Hence, the detection of change in the water salinity can be used to determine the correct usage of injected hydrate inhibitors.
Lowering the amount of inhibitors used within the well/pipe is beneficial because there is less amount of unwanted chemicals in the produced gas and oil, less associated production cost, less storage facility at the well site, less amount purchased, and less separation and re-injection of the inhibitor required. Additional production costs may also be lowered, such as the labor required for handling the inhibitors and pump requirements for introducing the inhibitor to the well. In addition, large dosages of inhibitors may cause undesirable byproducts such as foam and emulsions during the pumping process.
Finding the balance between the correct inhibitor dosage for each well can be challenging, especially due to increases in water-cut and/or water flow rate over time. Providing less inhibitors while still preventing hydrate formation can allow for flow assurance in the well pipe/pipeline and also reduce the associated production costs of the well.